The demand for crude oil has exceeded the existing production in the United States for more than 30 years, which has led to increasing demand for more imported oil and a dependency on foreign suppliers. Any new technology that could increase the efficiency of oil recovery would be of great benefit to countries such as the U.S. that have large amounts of unrecoverable oil in place (OIP) in older exiting oil fields.
Most of the remaining undeveloped oil in the Western Hemisphere is not light petroleum, but is heavy oil or tar sands. Large deposits of heavy oil are in Venezuela and California. Canada has large deposits of tar sands. Currently, production of heavy oil requires large amounts of energy.
Most petroleum is found in sandstone, siltstone or carbonate. Unlike natural gas, the recovery of petroleum oil is not efficient. The existing conventional oil production technologies are able to recover only about one-half of the oil originally in place in a reservoir of light oil. For heavy oil, the recovery is often less than 10%. Tar sands are so heavy that they will not flow at all and no oil can be recovered by conventional drilling and pumping. A technology that could recover a greater percentage of this residual oil could increase oil production from existing reservoirs and reduce the need of the U.S. for imported oil. The additional oil recovered from existing oil producing reservoirs could reduce the need to explore and develop wilderness areas that are potential new oil fields. This additional recovery of existing oil could bridge the gap needed for the development of alternative renewable energy sources.
The Original Oil In Place (OOIP) is the petroleum present in the oil reservoir when first discovered. The volume of the reservoir is determined by the size and porosity of the carbonate or sand stone. The porosity of the rock is a measure of the amount of small chambers or micro-traps within the rock that can hold water or oil. The oil is generally pushed up to the surface with the existing oil reservoir pressures at first, but the pressure in the oil well drops with time. Therefore, there is a need to create overpressure with other means such as water injection or a gas injection for secondary recovery of the OOIP. The choice of a specific secondary recovery technique depends on the type of the hydrocarbon accumulation and the nature of the reservoir. Water injection or “water sweep” or “waterflooding” is a common secondary recovery technique. In waterflooding, pressurized water is injected into the oil-bearing formation rock. Ideally, the injected water displaces the residual oil and moves it to a producing well. Generally in waterflooding, crude oil free of water is recovered first, and then subsequently a mixture of crude oil and water are recovered from the production wells. At some point, the percentage of water in the oil-water mixture (referred to as the water cut) from this technique becomes so high that it is uneconomical to continue pumping oil from the well. The problem, with using water as a “drive fluid”, is that water and oil are immiscible. The lower viscosity water will flow over the oil and by-pass large amounts of oil. Therefore, even after secondary recovery, a significant portion of crude oil remains in the formation, in some cases up to 75% of the OOIP. The fraction of unrecoverable crude oil is typically highest for heavy oils, tar, and large complex hydrocarbons. In the U.S. this residual OIP in old oil wells could be as much as 300 billion barrels of light oil. World-wide, the estimate of unrecoverable oil is 2 trillion barrels. There are an additional 5 trillion barrels of heavy oil, most of which is unrecoverable. Much of this remaining oil is in micro-traps due to capillary forces or adsorbed onto mineral surfaces (irreducible oil saturation) as well as bypassed oil within the rock formation.
Enhanced Oil Recovery
Oil recovery by injection of fluids not normally found in the reservoir is referred to as Enhanced Oil Recovery (EOR). It is a subset of Improved Oil Recovery (IOR), which can include operational strategies such as infill drilling and horizontal drilling. Although it is sometimes referred to as tertiary recovery, it can be implemented along with secondary processes. Many types of EOR have been proposed and used over the years. Technical complexity and the high cost of chemicals have prevented the widespread use of EOR to where it only represents about 10% of total United States oil production.
There have been two major EOR approaches; thermal and non-thermal.
Thermal Processes
Thermal processes work by heating the reservoir rock and the oil to reduce viscosity of the heavy oil. In general, the lower the viscosity of the oil, the better its recovery will be. The most widely used thermal process is steam injection in which the temperature of the reservoir and the remaining oil is increased by heat energy of steam. Hot water may also be used, but it is not as efficient at transferring heat to the oil and rock in the reservoir. Unfortunately, in both processes, most of the heat energy is lost to the surroundings and does not go to heating the oil. In situ combustion of the oil is much more efficient than steam because it only heats the reservoir and not all the pipes and overburden rock. However, in situ combustion is difficult to control and is seldom used. Typically, it requires the energy equivalent of a half a barrel of oil to recover a barrel of oil with a steam injected thermal process. However, this depends on the oil saturation and the configuration of the reservoir. Because most of the energy carried by the steam is given up to the pipes, wall rock, and reservoir, it is best to use only on reservoirs with a high oil content so as to recover as much oil as possible with the steam used to heat the reservoir rock. Generally, thermal methods are used on heavy oil because it reduces the viscosity of the oil and increases the mobility of the oil and the mobility ratio (mobility of displacing fluid to mobility of displaced fluid or oil). Typically, recoveries are in the range of 50 to 60% for a thermal process, but the net energy gain is much less than that because of the large amount of energy needed to make steam. The ideal situation for thermal oil recovery is when there exists a nearby source of inexpensive or waste energy for steam generation.
Non-Thermal Processes
Non-thermal methods are best suited for light and moderately viscous oils. The major objectives for these processes are to lower the interfacial tension (IFT) between the oil and displacing fluid and to improve the mobility ratio. Many of the non-thermal processes experimented with or used over the years rely on surfactants for reducing the oil viscosity and decreasing the IFT between the oil and displacing fluid. Ideally, the mobility of the displacing fluid should not be higher than the oil. The mobility ratio (mobility of displacing fluid over mobility of displaced fluid) should be low. The mobility of the oil can be increased by viscosity reduction and by IFT reduction. As the IFT is decreased, the oil becomes more miscible with the fluid until it becomes one phase and the IFT is zero. This decreases the mobility ratio and increases the oil recovery. Alternatively, the viscosity of the displacing fluid can be increased by adding polymers to “thicken” the liquid. Non-thermal methods require less energy and are best suited for light oil of 100 cp or less. However, most non-thermal methods require considerable laboratory experimentation and process optimization. The high cost of surfactants and polymers is generally the limiting factor for chemical EOR.
There are two major classes of chemical or non-biological EOR. One is miscible flooding with a displacing fluid that is miscible with the reservoir oil and will reduce the IFT to zero. The displacing fluids can be solvents such as propane or pentane or compressible gases that are also soluble in the oil. The temperature of the reservoir must be low enough so that the gas can be compressed to a liquid at the pressure that the reservoir can withstand without fracturing. Some examples of compressible gases are: natural gas, flue gas, nitrogen and carbon dioxide. Carbon dioxide has been gaining in prominence in recent years, partly due to the possibility of green house gas sequestration. The amount of carbon dioxide required to recover oil is substantial (500-1500 sm3/sm3 oil). Although these processes can recover up to 20% of the OOIP, their use is limited to a fraction of all reservoirs due to reservoir pressure and temperature requirements and availability of gases. Currently, in over 80% of all carbon dioxide gas EOR projects, the gas is delivered to the well site by pipeline from deep carbon dioxide mines in a few locations in the US.
The other major class utilizes a chemical formulation as the displacing fluid. The chemical compounds interact with the oil or the water or both in such a way that there is a decrease in mobility ratio and IFT which leads to better oil mobility and recovery. Chemical methods have a major advantage over both thermal and compressed gases in that they generally have lower capital requirements and are not limited by location and availability of gases or sources of inexpensive heat energy. Economics is the major deterrent to the use of chemical EOR. Many of the chemicals used in these processes are manufactured from petroleum and their cost increases as the price of oil increases.
There are four major chemical flooding processes.
Polymer flooding functions by improving the mobility ratio and reducing the permeability contrast of the reservoir. In most cases a slug of polymer solution of about 20 to 40% of the reservoir pore volume is pumped into the injection wells. Losses of polymer to the porous reservoir rock and degradation of the polymer due to shear forces can limit the success of the method. The polymers can be synthetic chemical polymers such as polyacrylamide or biologically produced such as polysaccharides. Some bio-polymers are more effective at high salinity than the chemical polymers, but are also more expensive to produce.
Surfactant flooding is effective by lowering the IFT between oil and water. A surfactant molecule has a polar group on one end of the molecule and a hydrophobic regain on the other end of the molecule. The ideal surfactant is one that will reside in both the oil phase and water phase at the oil water interface. Petroleum sulfonates or other petroleum compounds with a charged or polar group are often used as surfactants. Excessive loss of surfactant to reservoir rock surface and the high cost of surfactant production have limited the use of this process. However, surfactants can be used in combination with other chemical EOR methods to increase the performance.
Alkaline flooding and alkaline-surfactant-polymer (ASP) flooding takes advantage of acid compounds naturally found in some petroleum. In alkaline flooding, an aqueous solution of alkaline chemicals, such as sodium hydroxide, sodium carbonate or sodium bicarbonate is injected into a reservoir. The alkaline chemicals react with the acid compounds, also referred to as naphthenic acid, of the crude petroleum oil to form in situ surfactants on the surface of the oil. This causes a reduction in IFT and sometimes a spontaneous emulsification of the oil. The alkaline flooding is followed by a slug of surfactant and polymers in solution which can significantly increase oil recovery. The alkali also reduces adsorption of surfactant onto the surface of the formation rock and thereby decreases cost.
This process is limited to oil that has sufficient organic acid to be transformed into suitable surfactants. The amount of acid in the petroleum reservoir oil can be determined by extraction with base and then titration by hyamine or by direct titration of acid in an organic solvent. This analysis generates an acid number which is defined as the milligrams of potassium hydroxide need to neutralize the acids present in one gram or oil. It is generally believed that the target oil must have an acid number of 0.4 or more to be amenable to alkaline flooding. However, this is only approximate because a simple acid number does not provide details on the type of acids present in the oil. The direct titration of all the acid in oil is called the total acid number (TAN) and is generally much higher than the extracted acid titrated with hyamine. The TAN number is misleading because large hydrocarbon acids are too lipophilic to be extracted from the oil by dilute sodium hydroxide solution. These large lipophilic acids will also not function as good surfactants or soaps at the oil-water interface. Small hydrocarbon acids are too hydrophilic to be detected by the hyamine titration and are also not useful as soaps because they move into the aqueous phase and do not help lower the IFT of the oil. Therefore the best measure of the naphthenic acid is an aqueous extraction and titration with hyamine.
For petroleum reservoirs that contain unrecovered oil with an extractable acid number of 0.4 or more ASP flooding can be the lowest cost chemical EOR process. Unfortunately, most petroleum reservoirs in the U.S. do not have a sufficiently high enough extractable acid to be amenable to ASP flooding. Some shallow oilfields have high TAN which is believed by some to be the result of many years of microbial degradation. However, this slow natural process has also removed most of the alkanes and other lighter oil compounds leaving the residual oil very viscous. In 1998 A. K. Stepp and T. French proposed a process of first biodegrading oil to increase the TAN in order that the oil would be more amenable to ASP or alkaline flooding. The limitation of this proposed two step process is that the lighter molecular weight alkanes and aromatic hydrocarbons will be converted faster to fatty acids than the higher molecular weight hydrocarbons. Another problem is that many of the fatty acids that are produced will also be utilized as a carbon source by the injected microbes and the indigenous microbes.
Another limitation of a two step process is the first step of biodegrading the oil to increase the acid content can be a long process taking many months or years. The actual time needed to complete the biological conversion of hydrocarbons to fatty acids is variable and unpredictable. The ability to determine the actual acid content in the residual oil trapped within the underground reservoir is limited. Drilling into the reservoir formation for oil analysis is very expensive and is not a reasonable meriting technique. Starting the alkaline flooding too soon before enough acid were generated would not produce enough oil recovery because the TAN was too low. Delaying the start of the alkaline process would cause more degradation of light hydrocarbons and a loss of the light oil fraction with an increase in viscosity which would also delay the start of oil production.
Therefore there is a need to combine microbial oil degradation with alkaline and ASP flooding in such a way that high oil recovery can be achieved without loss of oil to extensive bio-degradation or lengthy multistep processes. The need is for a new alkaline process that it can be used on a larger number of reservoirs and that would reduce the chemical cost of the surfactants and polymers.
Microbial Enhanced Oil Recovery (MEOR)
One special type of EOR technique uses microorganisms such as bacteria and Achaea to dislodge the micro-trapped or adsorbed oil from the rock. The goal of this technique, which is known as microbial enhanced oil recovery (MEOR), is to increase oil recovery of the original subsurface hydrocarbons using microbes rather than the more costly chemical recovery processes. These biological processes typically use microorganisms to achieve similar results as the chemical methods in that they reduce IFT and reduce the mobility ratio of the water drive fluid to oil. The major mechanisms by which microbes are believed to function by are: (1) alteration of the permeability of the subterranean formation by producing low molecular weight acids from the biodegradation of hydrocarbons that cause rock dissolution, (2) production of biosurfactants that can decrease IFT and form micelles of oil in water in a way similar to chemical surfactants, (3) mediation of changes in wet-ability of the oil droplet by growing on the droplet and changing the surface of the oil to a less hydrophobic surface (4) production of bio-polymers that improve the mobility ratio of water to petroleum by increasing the viscosity of water and plugging high flow channels, (5) production of lower molecular weight hydrocarbons by enzymatically converting the large hydrocarbons into smaller molecules, which will reduce of the oil's viscosity, (6) generation of gases (predominantly carbon dioxide and nitrogen) that increase formation pressure.
Of all the EOR processes, MEOR is presently considered the lowest cost approach, but it is generally the least often used. One of the limitations of MEOR processes that stimulate indigenous microbes is that there is little control of the six proposed mechanisms of biological oil recovery. It is also possible that other unknown mechanisms are responsible for the more successful field tests of MEOR. Without better understanding or control of this biological process it is unlikely to be used to recover oil from large oil fields. In order to be used as other chemical or thermal oil production processes, it would be best if each of the above mechanisms could be tested separately.
Numerous microorganisms have been proposed for achieving various mechanisms of the microbial mobilization process in subterranean formations. Field tests of these microbes involved injection of an exogenous microbial population into old and low producing oil wells. The inoculating culture was supplied with nutrients and mineral salts as additives to the water pumped into wells for oil recovery. The development of exogenous microorganisms has been limited by the conditions that prevail in the formation. Physical constraints, such as the small and variable formation pore sizes together with the high temperature, salinity and pressure of fluids in the formation and the low concentration of oxygen in the formation waters severely limit the types and number of microorganisms that can be injected and thrive in the formation. Later, it became apparent that indigenous microbes stimulated by the nutrients were playing the major role in oil recovery. Accordingly, it is difficult to determine which of the various biological mechanisms were at work.
Biological constraints, such as competition from indigenous microbes and the stress of changing environments (from surface to subsurface) also act to limit the viability of exogenous microorganisms. To overcome these problems, the use of indigenous microorganisms, commonly anaerobic, has been proposed in MEOR projects. It is known that bacteria and other microbes can grow indigenously within petroleum oil reservoirs and can be used to enhance oil production. It is also known that bacteria and other microbes will metabolize various components of petroleum as a carbon and energy source. In addition to the beneficial effects of making surfactants, solvents and other metabolites that can result in an increase in oil production; they can consume oil as a carbon source. Unfortunately, they generally prefer to consume the short-length alkanes.
In fact, the process of petroleum bio-degradation relies on the emulsification of oil so that the hydrocarbon can be transported into the bacterial cells for conversion to fatty acids as a carbon and energy source. This process can be used to remediate oil spills and other oil contaminated sites by supplying the indigenous microbes with nutrients or inoculating with cultures of microbes that can degrade oil. In the case of biological remediation of petroleum contaminated sites, microbes can produce metabolites such as surfactants that help emulsify oil so that they can then use the emulsified oil as a carbon source. Both of these functions help remove the hydrocarbon contamination from the site. However, in the case of MEOR only the production of metabolites such as surfactants, bio-polymers, hydrocarbon cleaving enzymes, organic acids and solvents are beneficial to increased oil production. Other than providing an energy source, the consumption of light petroleum is not beneficial to enhanced oil production from the reservoir.
The biodegradation of the shorter carbon alkane chains reduces the lighter fraction of the hydrocarbon mixture in the petroleum oil. The removal of the short chain alkanes from this mixture increases the overall viscosity of the hydrocarbon mixture. The higher viscosity mixture is more difficult to recover from the reservoir. The percent of recoverable oil is decreased. Also, oil that is recovered is more difficult to transport through pipes and to refine. Therefore the production of useful compounds, by microbes for improved oil recovery, comes with a high cost.
This process of stimulating all the indigenous microbes in an oil reservoir by adding nutrients is unpredictable. The growth of the microbes may produce the beneficial effect of dislodging oil entrapped within a petroleum reservoir. Alternatively, the light oil consumption may make the oil more viscous and lower the total recovery of oil.
It would be less detrimental if all petroleum components were degraded equally, but the case is that the shorter chain alkanes and lower molecular weight aromatics are more readily degraded by the microbes as carbon and energy sources. Therefore, unless genes that code for short chain alkane or light aromatics are absent in all microorganisms both injected and indigenous it is likely that light hydrocarbon degradation will be faster than heavy hydrocarbon degradation. This is supported by the fact that petroleum deposits near the surface, and most subject to biodegradation, are generally rich in high viscosity oil and contain high levels of asphaltic hydrocarbon and fairly low on light (short) chain alkanes. Canadian tar sands are believed to be the heavy residue representing about 10% of the original petroleum deposit from which 90% of the oil has been degraded.
In the past, others have taught ways of augmenting the growth of microbes that dislodge and mobilize oil from underground petroleum reservoirs. These methods generally recommend adding nutrients. Some have also taught adding various cultures of selected bacteria that added beneficial capabilities. Some have even reported isolating microbes that can only degrade higher molecular weight hydrocarbons (see, e.g. U.S. Pat. No. 5,013,654). However, adding these selected cultures is not enough to achieve the desired result. Although these prior methods disclosed that microbes do exist that can only feed on high molecular weight oil, they failed to provide methods of increasing the bio-digestion of heavy oils, while suppressing the lighter weight hydrocarbon consumption by other indigenous microbes. The microbes that are naturally residing within the petroleum reservoir are likely to have the ability to degrade lower weight oil. Adding nutrients will generally stimulate the growth of all the microbes present. Because the smaller hydrocarbons can be transported across the cell membrane, the light weight oil consuming microorganisms will grow faster than those consuming high weight oil and will dominate the population that results from stimulation.
There are no methods in the art that effectively prevent the faster biodegradation of the light weight low-viscosity oil in comparison to the slower biodegradation of the higher weight viscous oil in the mixed culture of a petroleum reservoir. There are reports of pure strains of microbes that degrade only heavy oil (Purwasena I. A., et al. Proceeding of International Petroleum Technology Conference Doha, Qatar Dec. 7-9, 2009). However, there is no method of preventing the growth of indigenous short chain degrading microbes generally resident in most reservoirs at less than 80° C.
Therefore, the same process that is beneficial to oil recovery is also detrimental to oil viscosity; and it is known that increasing the viscosity of the residual petroleum held within the reservoir will decrease oil recovery.
Accordingly, there is a great need for new enhanced oil recovery approaches that are energy efficient, and can be reliably and successfully used in large field situations to enable the recovery of currently unrecoverable oil in existing oil fields. This new method should be able to selectively degrade certain target compounds found in the oil remaining in the subject reservoir so that the oil will be modified for better recovery by waterflood or by a chemical waterflood. Furthermore, the genes and the enzymes they code for can be modified and their expression regulated to best transform the oil for better recovery and production. The host microorganisms should be selected so that they survive the extreme conditions in the reservoir at the time of waterflooding or during a chemical EOR waterflooding.